Hydraulically driven gas recovery device and method of use

ABSTRACT

A gas recovery system where a submersible compressor is in combination with a hydraulic motor. The hydraulic motor is actuated by a pressure differential between hydraulic power lines extending between the motor and a pressure generation means at or near the surface. Hydraulic fluid serves to actuate device components and regulate the temperature of the down hole compressor. A monitoring system evaluates, communicates, and records operation parameters so that they may be adjusted to ensure a constant volume of produced gas. The device may operate at variable speeds to accommodate changing downhole pressure conditions.

CITATION TO PRIOR APPLICATION

This application claims the benefit of U.S. Provisional Application No. 60/647,068, filed Jan. 26, 2005.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention generally relates to a system for the recovery of gas. More specifically, the present invention relates to a system for the recovery of gas that is actuated by a hydraulic motor.

2. Background Information

Gas recovery devices heretofore devised and utilized are known to consist basically of familiar, expected and obvious structural configurations, notwithstanding the myriad of designs encompassed by the crowded prior art which have been developed for the fulfillment of countless objectives and requirements. While these devices may fulfill their respective, particularly claimed objectives and requirements, these devices do not disclose a gas recovery device and method of use such as Applicant's present invention.

Currently, numerous “dry” gas wells located in the United States produce gas through a production casing annulus. These wells are typically less than 3000 feet deep and contain an abundance of natural gas. In addition, these wells are often able to produce gas while having relatively low down hole pressure using techniques where surface pressure is brought down to near zero. That is, common recovery techniques involve surface compression facilities that reduce surface pressure to near vacuum. By exaggerating differential pressure along the bottom side of the well bore, the surface gas is free to flow from an area of higher pressure (downhole) to an area of lower pressure (the surface brought to vacuum). Nevertheless, an appreciable amount of gas cannot be recovered using this method. Invariably, an amount of gas equal to the hydrostatic head pressure of the gas column remains in the reservoir. Obviously, the amount of unrecovered gas directly depends on the depth of the well; as such, deeper wells necessarily withhold more unrecoverable gas

Gas reservoirs tend to be extremely prolific; that is, lowering the surface pressure by one pound per square inch (psig) may result in billions of cubic feet of additionally recovered natural gas. Nevertheless, known recovery techniques are unable to remove all of the natural gas contained in these wells. Most reservoirs are depletion driven, which dictates that the bottom hole pressure is constantly declining. As previously mentioned, at some point bottom hole pressure will decrease to a level where known recovery systems are unable to overcome the hydrostatic column of gas left in the well.

By way of example, “abandonment bottom hole pressure” in a 2000 foot well would be ±26 psi or a gradient of 0.013 psi/foot; likewise “abandonment bottom hole pressure” in a 3000 foot well would be ±39 psi or a gradient of 0.013 psi/foot. From these numbers alone, one can easily see that a plethora of unrecovered gas remains in the well. One does not have to look hard to see that the cumulative effect is tremendous; that is, as each well is left with an appreciable amount of gas, the sum of unrecovered gas becomes increasingly significant. It is estimated by those skilled in the art that trillions of cubic feet of currently unrecoverable gas remain downhole. At an approximate price of six dollars per MCF, the economic impact is clearly a significant one.

Those skilled in the art of gas recovery recognize the need to improve upon the recovery techniques known to be used. Until now, they have been met with two seemingly insurmountable obstacles: heat generated from gas compression and small diameter constraints of well bores (generally five inches or less). Each limitation, alone and in combination with one another, unduly limit the amount of gas that may be extracted from a gas reservoir. Skilled artisans have attempted to compress gas downhole in order to increase the pressure gradient between bottom hole and surface. However, increased heat associated with gas compression and higher downhole temperature typically causes compressor equipment to overheat. Also, attempts to place a compressor downhole have been hampered by the cramped dimensions of the well bore.

In view of the limitations mentioned above, a great need exists for an oil recovery system that can improve upon the percentage or recovered gas contained within an individual gas reservoir. Specifically, a gas recovery system is needed that can avoid the size and temperature constraints associated with compressing gas downhole.

SUMMARY OF THE INVENTION

The general purpose of the present invention, which will be described subsequently in greater detail, is to provide a new gas recovery system which has many of the advantages of those known in the art and many novel features that result in a new recovery system which is not anticipated, rendered obvious, suggested, or even implied by any of the known recovery systems, either alone or in any combination thereof.

In satisfaction of such, the present invention provides a gas recovery device and method of use incorporating use of a small I.D. rotary vane or other type of compressor driven by a hydraulic motor. Preferably, the compressor operates at or near the bottom of a well bore along the downhole end of a coiled tubing string and is placed at producing depth. A larger coiled conduit, having smaller coiled conduits contained therein, serves to conduct compressed gas from the compressor to the surface. The two strings of coil tubing having a smaller diameter, located inside the larger coil tubing string, serve as the hydraulic fluid conduits. In its most preferred form, differential fluid pressure of each hydraulic line actuates the hydraulic motor, which drives the compressor.

As previously mentioned, and to be later discussed, known compressors cannot effectively compress gas when placed downhole because of temperature related problems; specifically, compressors tend to overheat when used in such an arrangement. However, Applicant's invention solves this problem in elegant fashion. During operation, the heat generated by gas compression is absorbed by hydraulic fluid circulating along the peripheral portion of the compressor. The hydraulic fluid and compressor components are separated by a suitably rigid material that allows for effective thermal conduction. Further, when the fluid is circulating between the compressor and a pressure generating means, it may be cooled by any number of cooling means to further provide temperature regulation of the downhole compressor.

Perhaps the novelty of the present invention is most easily seen in that the amount of heat produced by the compressor is directly proportional to the flow rate of circulated hydraulic fluid. In other words, as the downhole gas pressure decreases (pressure gradient between downhole and surface decreases) the compressor is subject to a heavier workload, and more energy is required to compress the gas. As such, the flow of hydraulic fluid along the compressor must increase to accommodate the faster moving motor. Naturally, the increased flow of hydraulic fluid will more effectively dissipate the additional heat produced from the harder working compressor.

In its most preferred form, the present system is designed to provide a constant production rate. The production rate may be selected by the system user and evaluated and maintained by a control combination located at or near the surface. For instance, upon startup, the pressure deferential between the compressor inlet and outlet (or suction and discharge pressure) is at its lowest. This occurs when downhole gas pressure is at its highest and generally results in very good compressor efficiency. As the compressor runs, downhole pressure decreases, the compressor inlet and compressor outlet pressure differential increases, and more energy is required to compress the gas to maintain an established production rate. However, the motor (and likewise the compressor) variably operates to account for changing downhole conditions while maintaining constant production volume at the surface.

With known recovery devices (i.e., those driven by electrical means) motor speed remains constant and cannot be sufficiently varied to make up for varying pressure loads on the compressor. As such, production levels necessarily decline over time as the compressor runs. With an electrically driven compressor, production level variations often overload production facilities and pipelines, cause incorrect sales gas measurement, and create “bottlenecks” in transmission gas lines. However, the hydraulically driven gas compressor of the present invention can maintain a constant production rate by varying the flow rate of hydraulic fluid. It is envisioned that a variable speed electric motor would power the surface hydraulic pump to accomplish this goal.

BRIEF DESCRIPTION OF THE DRAWINGS

Applicant's invention may be further understood from a description of the accompanying drawings, wherein unless otherwise specified, like referenced numerals are intended to depict like components in the various views.

FIG. 1 is a cross section view of the preferred embodiment of the hydraulically driven gas recovery device of the present invention.

FIG. 2 is a flow chart type diagram of the preferred embodiment of the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

Referring to FIG. 1, the device of the present invention is generally designated by reference numeral 10. Device 10 is envisioned as being most beneficially used in the context of recovering natural gas from underground reservoirs. As such, device 10 is typically placed within a gas recovery production casing, which is generally designated by reference numeral 12.

Device 10 is characterized by hydraulic motor 14 located at the downhole side of a submersible compressor 16, which extends from production tubing 30. Hydraulic motor 14, in the preferred embodiment, is of a dimension suitable for placement within a standard sized gas reservoir (usually of a diameter of five inches or less) and preferably of a variable-speed type hydraulic motor actuated by differential fluid pressure. As will be later discussed, use of hydraulic motor 14, alone and in combination with other components, imparts several novel attributes to the device of the present invention.

In the most preferred embodiment, hydraulic motor 14 is driven by hydraulic fluid circulating through hydraulic power line high side 18 and hydraulic power line low side 20. Each hydraulic line runs along the length of production tube 30 in adjacent fashion and extends along the length of submersible compressor 16 where each is positioned between inner compressor housing 60 and outer compressor housing 32. Inner compressor housing 60 substantially encloses inner components of compressor 16 (i.e., rotary compression vanes). Preferably, inner compressor housing 60 is of a suitably strong material that allows efficient thermal conduction between compressor 16 components and power lines 18 and 20. Outer compressor housing 32 surrounds a substantial portion of submersible compressor 16, inner compressor housing 60, and hydraulic power lines 18 and 20 and is meant to protect and hold each in relation to one another.

The configuration of hydraulic power lines 18 and 20 in relation to compressor 16 is largely responsible for the unique operation of device 10. Hydraulic fluid serves to actuate, and regulate the temperature of, system components. During operation, hydraulic fluid circulating through each power line effectively regulates the temperature of compressor 16 as compressor 16 compresses fluid taken in through inlet 26. More specifically, the relatively cool hydraulic fluid serves to keep the component parts of compressor 16 from overheating during operation. Importantly, the amount of circulating hydraulic fluid is directly proportional to the operation speed of both hydraulic motor 14 and compressor 16. Therefore, as the operation speed of compressor 16 increases (and the higher its operating temperature would become) so does the speed at which hydraulic fluid circulates through each power line. This direct relationship between compressor operating speed and hydraulic fluid circulation speed provides for an excellent temperature regulation mechanism. As such, the device of the present invention is able to avoid the constraints associated with known devices.

At or near the surface, hydraulic power line 18 and hydraulic power line 20 are in combination with some power fluid circulating means 44 as known in the art. Power fluid circulation means 44 generates fluid pressure and flow for actuating motor 14. At its downhole end, hydraulic line 18 terminates at hydraulic motor 14 at high side inlet 34, and at its downhole end, hydraulic line 20 terminates at hydraulic motor 14 at low side inlet 36. Hydraulic motor 14 is actuated by a pressure differential between hydraulic power line high side 18 and hydraulic power line low side 20. Importantly, as the flow rate is changed, the speed of hydraulic motor 14 is changed. The particular hydraulic mechanism responsible for the actuation of hydraulic motor 14 is not critical; certainly, other suitable means for actuating motor 14 will be apparent to those skilled in the art.

Hydraulic motor 14 is in combination with submersible compressor 16 such that actuation of motor 14 causes actuation of compressor 16. As mentioned, in the preferred embodiment, submersible compressor 16 is a centrifugal rotary vane type pump as known in the art. These types of pumps are well known in the art; however, other useful embodiments are envisioned (and certainly will be apparent to those skilled in the art) where submersible compressor 16 is of some other type of pump. For example, other embodiments are envisioned where compressor 16 is a turbine pump or volute pump as known in the art. The compressor would probably have to be multi-staged to accomplish optimal compression due to diameter constraints.

As such, referring to FIG. 1, hydraulic motor 14 is shown in combination with a centrifugal rotary vane type submersible compressor 16. Actuation of motor 14 causes rotation of a central compressor drive shaft 22. Drive shaft 22 is centrally aligned along submersible compressor 16 and extends along a substantial length thereof. While not necessary for operation, compressor 16 is preferably a multistage compressor. A multi stage compressor 16 is preferred; as such, it is thought to be most useful for providing sufficient compression of the gas while having a sufficiently small diameter (preferably five inches or less).

During operation, a first stage compression occurs as gas taken in through inlet 26 is initially compressed as rotating element 40 (preferably an impeller) rotates within housing 60. Gas is led to the center of rotating element 40 and is set into rotation by rotary vanes 38. By virtue of centrifugal force, the gas is pressed from rotating element 40 and thrown from the rim or periphery of rotating element 40 with a considerable velocity and pressure. In this particular embodiment, when the rotor spins, centrifugal force pushes the vanes out to touch the casing, where they trap and propel fluid. Sometimes springs also push the vanes outward. When the vanes reach the return side they are pushed back into the rotor by the casing. Fluid escapes through a channel or groove cut into the casing.

As previously mentioned, the benefits achieved by the present system are not necessarily dependent on the specific type of compressor used. Particularly useful embodiments are envisioned where compressor 16 is a turbine compressor as known in the art. Where, during operation, recovered gas goes from intake to discharge (in just under one revolution) as it circulates along the compressor peripheral. Each time the gas passes the turbine blades it gains additional pressure. This embodiment is thought to be particularly efficient in the context of relatively low flow rates. Other embodiments are currently envisioned where compressor 16 is a volute compressor as known in the art.

Housing 60, which closely surrounds rotating element 40, has a volute shaped passage of increasing area, which collects gas leaving rotating element 40, and converts a portion of its velocity energy into additional pressure energy. This housing passage leads to a first discharge area where the initially compressed gas is again forced through the process described above one or more times. Useful embodiments are envisioned where compressor 16 has a balanced configuration where there are two inlet and two outlet ports. Such a configuration is thought to be particularly useful in eliminating any considerable unbalanced force on the drive shaft, that may occur where the high-pressure, outlet area is all on one side. Also, as one or more “compression chambers” may be stacked upon one another, each chamber may be staggered so that the compressor remains balanced during operation.

By virtue of the novel configuration of the present invention typical problems related to high temperature and size constraints are avoided. Hydraulic fluid circulating along the outside of compressor 16 serves to regulate the temperature of compressor 16 during downhole operation. Also, by having a series of rotating elements and rotary vanes 38 and discharge area combinations “stacked” upon one another, compressor 16 is able to achieve sufficient compression while being of a sufficiently small diameter to be placed in a typical production casing 12. These features, alone and in combination with one another, are not available with known systems.

Use of hydraulic motor 14 provides other novel benefits as well. As gas is recovered, the level of gas remaining in the well decreases; as such, the pressure gradient between downhole and surface decreases. When these compressors are driven by AC electric motors, as all such known compressors in this context are, production falls off with a decrease in production efficiency associated with the declining gas suction pressures. This decrease is rooted in the constraint that the electric motor maintains constant speed and power. It cannot accelerate or increase power to compensate for decreased downhole pressure. However, Applicant's invention avoids this limitation. The speed of hydraulic motor 14 may easily be increased in corresponding fashion to maintain a constant production volume.

Efficient operation of the present device is bolstered by complimentary components put in place to evaluate operation of the system and the produced gas. That is, in the preferred embodiment, controller means 50 serves to evaluate the operation of the device against a series of selected operational parameters. Preferably, although not exclusively, controller means 50 would work from differential amps to motor 14 and compressor 16. In this fashion, compressor 16 may start on a preset “slow power” setting and gradually ramp up to desired production parameters. As the fluid level descends in the well bore, additional power is necessary to produce the same volume of fluid (due to the decrease in pressure differential at surface and downhole). Necessary power (probably measured in amps load) should correlate to producing fluid level and production volumes. Finally, production volumes can be measured by measurement means 42. Measurement means 42 may be any of several types as known in the art, such as a differential flow meter produced by companies such as HALIBURTON and EDI. General operation of the preferred embodiment involves information received at measurement means 42 being sent to controller means 50. Controller means 50 may then carry out any number of functions (i.e., evaluate, compare, and record production volume and other parameters; adjust operation of hydraulic fluid circulating means 44) to better manage the operation of the device.

Although the invention has been described with reference to specific embodiments, this description is not meant to be construed in a limited sense. Various modifications of the disclosed embodiments, as well as alternative embodiments of the inventions will become apparent to persons skilled in the art upon the reference to the description of the invention. It is, therefore, contemplated that the appended claims will cover such modifications that fall within the scope of the invention. 

1. A gas recovery system comprising: a power fluid circulation means, said power fluid circulation means configured for imparting variable pressure and flow to power fluid; an elongate conduit means having a first end and a second end, said elongate conduit means being in substantially sealed fluid communication with said fluid circulation means at said first end; a fluid activated driving means, said driving means being in substantially sealed fluid communication with said elongate conduit means at said second end; a gas compressing means, said gas compressing means being mechanically engaged with said driving means, said compressing means being configured for placement in fluid communication with a subterranean gas source for conveyance of gas from said subterranean gas source substantially to a surface elevation.
 2. The system of claim 1 wherein said gas compressing means and said elongate conduit means are arranged such that a fluid circulating within said elongate conduit means may dissipate heat energy generated by said gas compressing means.
 3. The system of claim 2 further comprising a control means, said control means configured for controlling said power fluid circulation means.
 4. The system of claim 3 further comprising a measurement means in communication with said control means and configured for measuring said conveyed gas.
 5. A method for recovering gas from a subterranean source comprising the steps of: selecting a gas recovery system comprising: a power fluid circulation means, said power fluid circulation means configured for imparting variable pressure and flow to power fluid; an elongate conduit means having a first end and a second end, said elongate conduit means being in substantially sealed fluid communication with said fluid circulation means at said first end; a fluid activated driving means, said driving means being in substantially sealed fluid communication with said elongate conduit means at said second end; a gas compressing means, said gas compressing means being mechanically engaged with said driving means, said compressing means being configured for placement in fluid communication with a subterranean gas source for conveyance of gas from said subterranean gas source substantially to a surface elevation. positioning said gas recovery system to effectively recover said gas; and initiating operation of said fluid compressing -system. 